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December 21, 2025

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Stakeholder Soapbox: Is MISO Really an ‘Independent’ System Operator?

[Editor’s Note: This column does not represent the opinion of the Coalition of Midwest Power Producers or any of its members.]

By Karen P. and Mark J. Volpe

Mark Volpe writes about MISO and FERC Order 888
Mark Volpe | © RTO Insider

Last September, we documented the gradual departure of more than 25 GW of independent power producer-owned and -operated generation out of MISO.1 Today we will review and disclose the fundamental cause as to why merchant generation has been forced to exit MISO. As background, more than 22 years ago, the functional unbundling of transmission and generation assets as required under FERC’s landmark Order 888 was intended to promote wholesale competition among generators and preclude vertically integrated utilities from restricting access to the transmission system in order to favor their own generation resources.2 The first and most important fundamental characteristic FERC defined was independence, and those RTOs approved as consistent with Order 2000 were required to be independent in their decision-making process, with FERC explicitly stating, “the regional transmission organization must have a decision-making process that is independent of control by any market participant or class of participants.”3 My late wife, Karen, had always questioned the entire concept of “ISO independence,” dating back to the end of my time at FirstEnergy in 1997, when she steadfastly maintained that an ISO’s independence was never a realistic hypothesis because the ISO’s decision-making process would never be the product of truly independent thinking. Karen loved to ponder and debate the question of independence with family, where she concluded there was no such thing as independence. When dealing with the human element, she insisted that once we are born, it is universally true that because the human condition it is not possible to be independent. Each and every living being evolves and grows and gradually becomes a product of their environment based on their life’s experiences.

To address this reality, the ISO’s senior management must be populated with industry experts with a deep-seeded awareness and responsibility that it is incumbent upon the RTO/ISO to remain fair and balanced in its decision-making process and not appeal solely to the interests of those business models representing the majority. Unlike the rest of the country, RTOs are not a democracy subject to majority rule; instead, they are supposed to be independent and also represent the interests of those in the minority. The MISO transmission owners are collectively a class of participants, which, except for the standalone transcos, are composed of vertically integrated utilities that also own and operate a significant amount of affiliated generation assets. As such, MISO is purportedly independent and precluded from making market design decisions that would favor the TOs, which have voluntarily transferred functional control of their assets over to the RTO. This lack of independence is not unprecedented, given MISO senior management’s favoritism of certain TOs, including Ameren, Northern Indiana Public Service Co. and FirstEnergy in the context of a preferential and more lucrative distribution of revenue sufficiency guarantee payments, which was the subject of a nonpublic investigation performed in 2007 by the FERC Office of Enforcement (IN07-32).4

In 2011, things really “hit the fan,” as MISO received FERC acceptance of its current Planning Resource Auction design, relying on a fundamentally flawed vertical demand curve under a residual capacity construct.5 This design certainly favored the incumbent TOs because by operating under a vertical demand curve, even the slightest surplus results in near zero auction clearing prices that cannot sustain merchant generation over the long term and has resulted in the continued inevitable demise of merchant generation. More recently, in a protest concerning MISO’s refiling of its entire PRA construct, which has resulted in unreasonably low auction clearing prices ranging from $1.50 to $10/MW-day in recent years, the RTO’s own Independent Market Monitor, David Patton, stated:

“The commission relies on well-designed competitive markets to produce prices and market outcomes that are just and reasonable. No objective analysis of the MISO capacity market could demonstrate that the outcomes under the current Module E are just and reasonable by any appropriate standard. In fact, the flawed design of the market precludes it from producing just and reasonable prices. … Further, MISO made no attempt to provide evidence that its capacity market has produced reasonable outcomes or that it is an economically sound market design.”6

Cumulative MISO Capacity losses - in spite of FERC Order 888 intent
| Coalition of Midwest Power Producers

Patton has demonstrated that with a properly shaped demand curve, the auction clearing prices would be in the range of $65 to $150/MW-day. The vertically integrated entities comprise 95% of the MISO market and are subject to traditional cost-of-service regulation administered by state regulatory commissions, where, based on publicly available FERC Form 1 data, the affiliated generators received on average $300/MW-day for capacity cost recovery as collected within the utilities’ bundled retail rates. In filing this flawed approach, and arbitrarily favoring the generation assets affiliated with the MISO TOs back in 2011,7 the underlying silent intent on MISO’s behalf was aimed at ensuring the remaining TOs stayed put in the RTO and has forced a large majority of the merchant generators to exit, leaving the TOs owning generation with the dominant market share.

While Order 888 promoted open access to the grid, MISO’s TOs still retain significant influence and leverage over MISO’s market design decisions, given the ever present veiled threat to pull their assets out. This has resulted in an inherent bias on MISO’s behalf to support a capacity construct that favors “The Owners” and their affiliated generators. It’s no coincidence that FERC accepted MISO’s flawed capacity construct right after FirstEnergy and Duke Energy Ohio had decided to leave MISO for PJM’s better designed forward capacity market. The continued departure of otherwise economic merchant owned generation will eventually leave consumers in a “market” dominated solely by the incumbent vertically integrated utilities owning the major market share of MISO’s total generating capacity. The Organization of MISO States needs to do what is best for their ratepayers because consumers will be harmed and eventually see a rise in prices given the absence of competitive supply alternatives.

Promoting competition among wholesale generators was one of the cornerstones of Orders 888 and 2000 and has been severely compromised because of a lack of independence in MISO. This is not the result of unintended consequences. Wholesale competition in MISO is in danger of extinction given the rapid departure of competitive merchant generation. The facts demonstrate MISO purposely and consciously designed its resource adequacy construct to unduly discriminate against the economic interests of merchant generators in violation of the independence requirement, by arbitrarily benefiting the financial interests of those generation assets affiliated with MISO’s vertically integrated TOs. This untenable situation is not working as originally envisioned by our federal regulators in D.C., where Orders 888 and 2000 were designed to promote wholesale competition among generators — not kill it!

Mark J. Volpe is the president & CEO of the Coalition of Midwest Power Producers (COMPP), a nonprofit trade association focused on the continued evolution of fully robust wholesale energy and capacity markets in MISO. He is the former Senior Director of Regulatory Affairs for Dynegy Inc.This column does not represent the opinion of COMPP or any of its members.] 

1RTO Insider, “The Slow Death of Merchant Generation in MISO,” Sept. 17, 2018.

2FERC Order No. 888, Docket No. RM95-8-000, et al., 75 FERC ¶61,080, April 24, 1996.

3FERC Order No. 2000, Docket RM99-2000, 89 FERC ¶ 61, 285, Dec. 20, 1999.

4FOIA FY 2011 Log Report – Federal Energy Regulatory Commission.

5Midwest Independent Transmission System Operator, Inc. Filing to Enhance RAR By Incorporating Locational Capacity Market Mechanisms (“Resource Adequacy Filing”), Docket No. ER11-4081-000 filed July 20, 2011, and order accepting MISO Resource Adequacy Proposal, 139 FERC ¶61,199, June 11, 2012.

6See Motion to Intervene Out of Time and Protest by MISO’s Independent Market Monitor, FERC Docket No ER18-462, page 4, Feb. 7, 2018.

7Resource Adequacy Filing at 2.

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NIPPC Members ‘Carry On’ Without Kahn

By Hudson Sangree

UNION, Wash. — Sadness over the recent death of Robert Kahn suffused this year’s annual meeting of the Northwest & Intermountain Power Producers Coalition, where speakers remembered and praised the energy veteran.

Remembering Robert Kahn, NIPPC executive director

Attendees remembered Robert Kahn, NIPPC’s former executive director, who died in August. | © RTO Insider

Kahn, the longtime executive director of NIPPC, died in early August following a brief battle with cancer.

In addition to his policy expertise and advocacy, Kahn was known for organizing the trade group’s annual meeting at the Alderbrook Resort & Spa on Washington state’s Hood Canal, a natural fjord that’s part of Puget Sound.

In a lunchtime address, Elliot Mainzer, head of the Bonneville Power Administration, acknowledged the rain pouring outside the hotel conference room Sept. 9.

“I think it’s pretty appropriate the sky is shedding a few tears today for Bob,” Mainzer said as he began his remarks.

“Bob was a really good friend,” he said. “He was a guy who could take you to task and then join you for a beer. [He was] one of a kind. We’re going to miss him.”

A sign memorializing Kahn stood at the entrance to the meeting. It implored members to “Carry On!” — one of Kahn’s favorite expressions.

NIPPC’s lifetime achievement award was renamed for Kahn this year. Before he died, Kahn selected its recipient, Randy Hardy, a former BPA administrator and superintendent of Seattle City Light.

“I can think of no one more deserving,” Kahn had written.

Hardy introduced the meeting’s final presenter Sept. 10, Arne Olson of Energy and Environmental Economics.

Alderbrook Resort, site of the NIPPC Annual Meeting

NIPPC holds its annual meetings at the Alderbrook Resort & Spa on Hood Canal, a fjord in rural Washington state. | © RTO Insider

“I felt his presence throughout this event, even in his absence,” Olson said. “I think that says a lot about the size of his personality, that he can still dominate this event; the event can still be Bob’s event, even after he’s gone. I think that personality will really be missed in the region.”

Olson said Kahn used his standing in energy circles to be “a thorn in the side of the utilities, a persistent advocate for competition and a breath of fresh air from the outside in an industry that, from my perspective, really, really needs that.”

Regional Markets

As in prior years, much of the discussion at this year’s NIPPC meeting revolved around participation in Western regional markets. (See Northwest Ponders RTO with Mix of Hope and Skepticism.)

As part of a carbon policy panel, Glenn Blackmon, with the Washington State Energy Office, noted his state recently passed a bill mandating electric utilities to rely on renewable and carbon-free energy sources by 2045. California passed a similar bill last year.

NIPPC Annual meeting panel on carbon policy

A panel on carbon policy included David Mills, Puget Sound Energy; Glenn Blackmon, Washington State Energy Office; and Kristen Sheeran, Oregon governor’s office. | © RTO Insider

The measure, SB 5116, is far more detailed than California’s landmark SB 100 but still requires policymakers to tackle thorny problems, he said.

“One of those areas is figuring out how to make our clean electricity policy work with the regional markets,” Blackmon said. “We want to make sure that our utilities and other power suppliers are able to participate [and] get the benefits of organized markets. But we also want to make sure we meet the clean electricity objectives of our statute.

“We’d like to see the markets develop in a way that if you want to trade clean … you’re able to do that,” he said.

CAISO’s Western Energy Imbalance Market and SPP’s new Western Energy Imbalance Service (WEIS) are generally seen as a way to buy and sell clean energy across the Western Interconnection. Concerns linger, however, about the uneasy alliance between the coal-burning states of the interior West and coastal states seeking to go all-green. (See Patchwork of Carbon Policies Troubles Western EIM.)

Both markets continue to sign up new customers, though the EIM remains far larger than its nascent challenger at SPP. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)

“It looks like there is going to be meaningful competition for market platforms in the West, which I think is a good thing,” Steve Wellner, FERC’s director of Western regulation, said at the NIPPC meeting.

If BPA joins the EIM, as it hopes to do by 2022, it would bring an area of the Pacific Northwest the size of France into CAISO’s interstate wholesale trading market. In June, BPA kicked off a monthlong public comment process in hopes of signing an implementation agreement with the EIM this month. (See Customers Probe BPA on EIM Impact.)

“We got 100% support for signing that agreement,” Mainzer told the NIPPC audience.

Elliot Mainzer, BPA, addressing the NIPPC Annual Meeting

Elliot Mainzer, head of the Bonneville Power Adminstration, addressed NIPPC members at lunch Sept. 9. | © RTO Insider

CAISO is evaluating adding an extended day-ahead market (EDAM) to the real-time EIM to increase its usefulness as a regional marketplace, and the BPA administrator said he believes the EDAM is needed to help move BPA’s hydropower and other renewable resources across the West.

“It’s not going be enough to sell all this stuff on a five-minute market,” Mainzer said.

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PG&E and Insurers Agree to Settle Wildfire Claims

By Hudson Sangree

PG&E Corp. announced Friday it had reached an $11 billion settlement agreement with nearly all the insurers trying to recoup their payments to victims of wildfires sparked by the utility’s equipment in the past two years.

The insurers — collectively known as the Ad Hoc Subrogation Group — were the second largest bloc financially, after wildfire victims, that PG&E had to confront in its Chapter 11 reorganization proceedings begun in January.

The agreement must be approved by the bankruptcy court, along with other settlement offers by PG&E. The company had already agreed in June to settle claims by local governments and agencies against it for $1 billion.

“Today’s settlement is another step in doing what’s right for the communities, businesses and individuals affected by the devastating wildfires” of 2017 and 2018, PG&E CEO Bill Johnson said in a news release.

PG&E is attempting to exit bankruptcy by June 2020 to be able to take advantage of a new $21 billion wildfire recovery fund established by the state of California to compensate fire victims. The fund was created by Assembly Bill 1054, passed in July. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)

It’s also trying to head off what’s essentially a hostile takeover attempt by its unsecured bondholders, which have offered PG&E a $30 billion cash infusion in exchange for a controlling interest in the utility and guaranteed payment of their notes. (See Judge Weighs Competing PG&E Bankruptcy Plans.)

In a separate statement, the Subrogation Group said it was accepting a settlement that’s a little more than half of what insurers claim they’re owed.

“While this proposed settlement does not fully satisfy the approximately $20 billion in group members’ unsecured claims, we hope that this compromise will pave the way for a plan of reorganization that allows PG&E to fairly compensate all victims and emerge from Chapter 11 by the June 2020 legislative deadline,” it said.

The deal PG&E struck with insurers is $2.5 billion more than the trust, capped at $8.5 billion, that PG&E proposed in its reorganization plan filed Sept. 9. In that plan, $16.9 billion was to be split about equally between individual wildfire victims and insurance companies. (See PG&E Offers $16.9B for Wildfire Claims in Chap. 11 Filing.)

Whether the increase for insurers means wildfire victims could get less will be determined in court, but victims’ lawyers had already criticized PG&E’s initial plan of compensation as falling far short of what they deemed acceptable.

PG&E filed a document Friday with the U.S. Securities and Exchange Commission showing it had secured promises of $14 billion in new equity investment to help cover its wildfire payment plan. It also said it was increasing its total compensation package for victims, insurers and local governments by $1 billion — still $1.5 billion short of Friday’s proposed increase for the subrogation claimants.

PG&E filed for bankruptcy in January, saying it couldn’t afford at least $30 billion in wildfire claims from a series of deadly and hugely destructive fires in 2017 and 2018.

Investigators with the California Department of Forestry and Fire Protection (Cal Fire) said PG&E equipment sparked November’s Camp Fire, the deadliest and most destructive in state history, and a rash of fires in Northern California wine country in October 2017.

PG&E is till being sued for the Tubbs fire
Insurance is helping homeowners rebuild from the Tubbs Fire, which destroyed part of Santa Rosa, Calif. | City of Santa Rosa

Cal Fire determined a private landowner’s faulty wiring started the Tubbs Fire, which leveled part of the city of Santa Rosa, killed 22 people and caused billions of dollars in damages in October 2017. But Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, allowed fire victims and insurers to move ahead with lawsuits in state court that blame PG&E for the Tubbs Fire.

Friday’s settlement includes the Tubbs Fire, a PG&E spokeswoman said, though the lawsuit remains active for now, pending the bankruptcy court’s approval of the settlement.

PG&E’s beleaguered stock price rose nearly 11% after Friday morning’s announcement, going from $10.10/share at close of trading Thursday to $11.18/share by 4 p.m. Friday.

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MISO Unruffled by Fall Supply-demand Outlook

By Amanda Durish Cook

CARMEL, Ind. — MISO doesn’t expect any challenges meeting demand this fall, announcing last week that its supply should outpace its relatively tame peak forecast by about 36 GW.

The RTO estimates it will have 148 GW in total available capacity for the season, plenty to cover an expected 112-GW fall peak.

Jenna Furnish discussing MISO's probable load for fall
MISO’s Jeanna Furnish | © RTO Insider

“That 112 GW is 3 GW lower than what we experienced in September 2017,” Jeanna Furnish, MISO manager of outage coordination, said at Thursday’s Market Subcommittee meeting.

But in keeping with the past several seasonal assessments, the RTO was careful to say that high-load, high-outage scenarios could trigger emergency procedures.

To generate its load forecasts, MISO partly relies on data from the National Oceanic and Atmospheric Administration, which has predicted higher-than-normal temperatures for the southern and eastern portions of the RTO’s footprint.

Furnish began the seasonal outlook by polling stakeholders on a family dispute. “When does fall start? The astronomical definition of Sept. 23 at 3:50 a.m. [EDT], or the meteorological definition of Sept. 1?”

Those at MISO’s headquarters overwhelmingly favored the astronomical approach.

MISO’s fall, however, is effective throughout September, where the risk of emergency procedures is most pronounced in the face of high load. During the month, the RTO could dip into its load-modifying resources and operating reserves in a 117-GW, high-load scenario even when outages aren’t considered a problem.

Furnish said a high-load, high-outage scenario paints a “bleaker picture” in which MISO might use the top end of its 13.7 GW in reserves. However, the RTO expects an average 111.3 GW of probable load during September. In October and November, MISO load is not expected to exceed 96 GW, and probable load will likely hover around 90 GW.

Furnish ended by joking she wouldn’t be doing her MISO duty if she didn’t urge members to submit outages as early as possible.

“Please make sure your company’s outages are in, for not only this fall, but also next spring. … It’s never too early to think about spring,” she said.

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Anticipating Boom, MISO Extending Dispatch to Solar

By Amanda Durish Cook

CARMEL, Ind. — After experiencing a surge in new projects, MISO is hoping bring solar generation under the umbrella of its dispatchable intermittent registration for market participation, the RTO signaled last week.

MISO’s proposal, issued Thursday, seeks to put solar generation on par with wind generation in the dispatch process. The method to be used provides a bit of déjà vu for some seasoned stakeholders.

Ken Zhu discussing how MISO would like to handle solar projects
Kun Zhu, MISO | © RTO Insider

Kun Zhu, MISO manager of resource retirement, said the proposal was precipitated by the flood of solar projects lining up for interconnection. “Quick story: Based on what’s coming in the queue, we’re set to have a big surge in solar,” he said in opening the Market Subcommittee meeting Thursday. “Now we expect the same challenge we saw 10 years ago,” referring to the wind generation boom that took hold about a decade ago.

Zhu said MISO’s plan is to require future commercial solar generation to register as dispatchable intermittent resources (DIRs), as it does for wind resources. Currently, solar generators can choose to be DIRs or simply remain intermittent resources, which are price-takers in the market and ineligible for dispatch. DIRs can submit price-sensitive offers and be dispatched by the market.

While MISO currently has just 243 MW of solar under the DIR registration, it reports that more than 9 GW worth of solar projects have executed generation interconnection agreements or are close to doing so. Beyond that, about 52 GW of solar are in the early stages of the interconnection study process.

“The time is now to expect the challenge and mitigate it,” Zhu said, adding that MISO can avert the growing pains it experienced in 2008 and 2009 when operators had to initially manually curtail wind generation over the phone. “It was cumbersome and not optimal and not ideal, and it caused big challenges in the control room.”

MISO won FERC approval in 2011 to create the DIR category for wind.

“We’re bringing solar to the same playground as wind,” Zhu said, pointing out that FERC recently accepted a similar change to solar treatment in SPP.

Just as in the original DIR filing for wind, MISO is proposing a two-year transition period to register solar resources. Solar projects with interconnection agreements before the time of the filing have two years to convert from intermittent resources to DIRs. Solar projects with no interconnection agreement in place before the effective date of the new tariff rule must register as DIRs immediately with no grace period.

Solar projects in the MISO interconnection queue
MISO

Customized Energy Solutions’ David Sapper asked how the proposal would treat hybrid solar and storage projects.

Zhu said the hybrid angle is outside the scope of the proposal — for now. MISO is holding a special workshop in early October to discuss the rules and implications around hybrid projects. (See MISO to Host Hybrid Projects Workshop.)

“Hybrid is a new topic. What we’re discussing now is 100% pure solar generation, limited by the weather,” Zhu said.

MISO hopes to make a Tariff filing sometime in December.

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FERC Orders Expanded Mitigation for LGE-KU

By Rich Heidorn Jr.

FERC last week rejected Louisville Gas & Electric and Kentucky Utilities’ proposed transition for exiting from market power mitigation measures the commission had imposed to address the companies’ 1998 merger and withdrawal from MISO in 2006 (ER19-2396, ER19-2397).

The rate de-pancaking mitigation provisions were imposed to resolve horizontal market power concerns. In March, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers after the mitigation is removed. It conditioned the removal on a transition mechanism to protect customers that had relied on transmission service on the MISO system.

FERC said that “although it determined that there would continue to be a sufficient number of competitive suppliers in the LG&E/KU market if the de-pancaking mitigation was terminated, termination will affect the relative economics of competing suppliers in different markets by making the cost of purchases from resources located in MISO more expensive.”

Eligible for the transition were contracts by the Kentucky Municipal Power Agency to supply KU requirements customers that went into effect on May 1; a requirements contract between the city of Benham and American Municipal Power; a requirements contract between the city of Berea and AMP that went into effect on May 1; and a contract between the city of Owensboro and Big Rivers Electric Cooperative.

The commission said the proposed transition mechanism filed by the companies in July was overly narrow and spelled out changes the companies must make regarding which customers and power purchase agreements should be covered and the definition of “covered” transmission service requests. It also ordered changes regarding which MISO schedules are eligible for reimbursement, reimbursement adjustments and the handling of exports.

In an accompanying ruling rejecting rehearing of its March order, the commission also identified three additional customers as eligible for the transition: KYMEA and member cities Paducah and Princeton (EC98-2-002, ER18-2162-001).

LG&E serves 411,000 electric customers in Louisville and 16 surrounding counties. KU serves 553,000 customers in 77 Kentucky counties and five counties in Virginia. The two companies, which are now PJM members, are owned by Allentown, Pa.-based PPL.

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NYISO Business Issues Committee Briefs: Sept. 11, 2019

The NYISO Business Issues Committee on Wednesday approved revisions to Manual 4 (Installed Capacity) for external capacity suppliers, with a focus on imports from Ontario’s Independent Electricity System Operator and ISO-NE.

Section 4.9.1 was amended to add detail to the requirements for qualifying as an external capacity supplier. It requires a demonstration of deliverability to the New York Control Area border and execution of a letter certifying the supplier’s control of the resource if it does not own it.

Because the yellow ISO-NE capacity zone was identified as “import-constrained,” ISO-NE transmission is not able to accommodate the generator delivering to the New York border. Without an export delist bid, the generator would not be eligible to sell capacity in NYISO auctions. | NYISO

Section 4.9.3 was changed to add delivery requirements for imports from Ontario and New England. Suppliers from Ontario must provide written proof that IESO has approved their exports of power. Suppliers in New England must provide proof that they have an approved export delist bid in the ISO-NE Forward Capacity Market, or that it is not located in a capacity zone that does not permit exports.

FERC Updates

Presenting the Broader Regional Markets report, Robb Pike, director of market design and product management, provided updates on two recent FERC rulings, including one on external capacity.

On July 30, the commission accepted the ISO’s proposal to implement new requirements for external installed capacity suppliers responding to a supplemental resource evaluation (SRE), effective Aug. 12. Any external resource that fails to meet delivery criteria will be subject to a penalty of 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond (ER19-2104).

On Aug. 28, FERC accepted revisions to the NYISO-PJM Joint Operating Agreement, effective on Sept. 26, to address a previous waiver approved by FERC regarding coordination of certain types of flowgates.

NYISO and PJM asked FERC to waive the JOA to permit the grid operators to add the East Towanda-Hillside Tie Line as a market-to-market flowgate. The requested waivers enable PJM to conduct redispatch operations to control flows to the more restrictive rating on the NYISO side of the tie line without violating the PJM Tariff for a limited period of time while NYISO and PJM develop a permanent solution.

Other Manual Changes

The BIC also approved changes to Manual 14 (Accounting and Billing) that replaces the terms “meter service provider” and “meter service data provider” with “meter authority.” It also revises Section 4.3.3 to clarify the methodology for certain calculations.

The committee also approved changes to Manual 27 (Revenue Metering Requirements) to add definitions of “member systems” (the eight transmission owners that comprise the New York Power Pool) and “meter services entity” (an entity registered with the ISO and authorized to provide metering and meter data services to an aggregator, responsible interface party or curtailment service provider).

LBMPs Decline 16% in August

NYISO locational-based marginal prices averaged $27.83/MWh in August, down approximately 16% from July and nearly 35% from the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $34.96/MWh, a 25% decrease from a year ago.

Day-ahead and real-time load-weighted LBMPs came in lower compared to July. Average daily sendout was 487 GWh/day in August, lower than 539 GWh/day in July and 537 GWh/day in the same month a year ago.

Transco Z6 hub natural gas prices averaged $1.85/MMBtu for the month, down over 15% from July and 38.3% from a year ago.

Distillate prices were down 15.1% year over year and down slightly from the previous month, with Jet Kerosene Gulf Coast averaging $13.32/MMBtu, compared to $14.18/MMBtu in July, while Ultra-low Sulfur No. 2 Diesel NY Harbor dropped to $13.02/MMBtu from $13.71/MMBtu in July.

August uplift decreased to -20 cents/MWh from -6 cents/MWh in July, while total uplift costs, including the ISO’s cost of operations, came in lower than those of the previous month.

The ISO’s 25-cents/MWh local reliability share in August was down from 44 cents/MWh the previous month, while the statewide share climbed to -45 cents/MWh from -50 cents/MWh in March.

The Thunderstorm Alert cost was 33 cents/MWh.

— Michael Kuser

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FERC Sends DER Data Request to RTOs

By Amanda Durish Cook

FERC is asking RTOs for information on aggregated distributed energy resource portfolios in their wholesale markets — the first significant movement in a possible rulemaking on DER in more than a year.

On Sept. 5, FERC’s Office of Energy Policy and Innovation sent identical letters to all the RTOs and ISOs seeking data on their existing aggregated DER interconnections (RM18-9).

“Commission staff is interested in further exploring the interconnection of distribution-connected DERs, in particular those that participate or will participate in DER aggregations for the purpose of providing wholesale service in markets operated by [RTOs/ISOs],” FERC said.

The commission asked for responses by Oct. 7, which will be followed by a 30-day comment period.

The 11-question list asks RTOs to provide data or estimates on the number of DERs in each footprint that directly participate in wholesale markets versus the DERs that don’t participate. FERC also inquired about RTOs’ coordination with state and local leadership about DER interconnection processes.

More detailed questions delve into each RTO’s “step-by-step” interconnection process for DERs and whether the process differs if DERs are eligible qualifying facilities or are behind a retail customer meter. FERC also asked how an aggregation of DERs located at multiple points of interconnection are studied, whether RTOs have interconnection studies for bidirectional service and how an RTO would handle a study for individual, already-interconnected DERs that wish to aggregate from separate points on the grid. Finally, the commission asked how the RTOs manage DERs aggregating from both FERC-jurisdictional and non-jurisdictional distribution facilities and requested the number of distribution facilities subject to an open access transmission tariff.

RTOs and ISOs this week said they were working to prepare data submittals.

Spokesperson Meghan Sever said SPP is working to provide FERC with “as much of the requested detailed DER data as possible” by the early October deadline.

DER

| © RTO Insider

MISO said it is working with the Organization of MISO States — which has developed its own DER estimates — and its stakeholder community to understand DER interconnection across the transmission and distribution interface.

“MISO has assembled a team of its subject matter experts who are reviewing the specific data requests and developing information to provide the requested information,” spokesperson Allison Bermudez said in an email to RTO Insider. “We will continue to coordinate with OMS and other stakeholders as we evaluate our responses.”

ISO-NE also said it was working to comply with the request. NYISO said it wouldn’t comment on preparations beyond its “official response to FERC.”

AEE Welcomes Movement

Leadership at Advanced Energy Economy, a D.C.-based trade association with members who develop and use DERs, took the data requests as a good omen. “We think it’s a good sign that the commission continues to dig into the issue and put some focus on it,” said AEE Managing Director and General Counsel Jeff Dennis, who leads the group’s wholesale markets advocacy.

But Dennis warned that the newest action in the DER docket now leaves any new rule waiting at least until November, and probably longer. With a draft DER rule still in a holding pattern, AEE released a white paper Sept. 5 outlining five case studies where DERs can be beneficial in wholesale markets. Dennis said the paper illustrates how DERs can provide service in wholesale markets to the benefit of consumers and the grid.

“As we await a final rule from FERC, there is a lot of discussion of the challenges to [DER participation] in wholesale markets. We wanted to focus on the benefits and the fact that this is already happening,” AEE Director Caitlin Marquis said of the five scenarios, which include managing demand or load with solar generation, battery storage, electric vehicle fleets and microgrids.

The case studies include a microgrid that can participate in wholesale energy and demand response markets to bolster vulnerable points on the grid or help during extreme weather; aggregated battery storage installations used for demand charge management; and electric vehicle fleets that are responsive to demand. The paper also highlights commercial solar generation and storage installations used to meet corporate sustainability goals and reduce wholesale market load and aggregated residential solar/storage facilities that have cleared ISO-NE’s forward capacity auction.

“This is what we could have more of if there were rules in place,” Marquis said, noting that some of the case studies are based on actual DER setups from AEE’s member companies.

Dennis also said there’s no harm in RTOs doing more work now to prepare for a DER rule.

“What we really want to see is additional efforts by RTOs and their stakeholders to look at how DERs will contribute to the wholesale markets in the future. Many RTOs are starting to do this now, and we hope others will follow suit,” Dennis said. “What’s really going to be needed beyond that though is RTOs taking a full look at their markets and the services that DERs can provide in those markets … and then ensuring that there are market participation pathways for them to do that.”

Dennis said AEE staff is also meeting with some RTOs to emphasize the benefits of aggregated DERs and discuss operational characteristics and implications for long-term system planning.

“Their experience so far is with large, central station power plants,” Dennis said of the RTOs. “We want to help them shift their thinking and approaches to prepare for the grid of the future, which will include many more distributed resources.”

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SPP Seams Steering Committee: Sept. 11, 2019

SPP staff told the Seams Steering Committee on Wednesday that they are evaluating internal procedures and improving situational awareness for its operators following a level 1 energy emergency alert in early August, the RTO’s first since it became a consolidated balancing authority in 2014.

The grid operator called the EEA on Aug. 6 when capacity losses, a “significant” load-forecast error and low wind production led to tight operating conditions. The final straw came at 1:30 p.m., when a 290-MW generator tripped offline.

Load came in 1,500 MW over forecast as temperatures were higher than expected. The system also lost 2,500 MW of capacity in unplanned outages.

The Aug 6th event was discussed at the SPP Seams Steering Committee
Aug. 6 load, generation and imports | SPP

The RTO was able to escape the situation by calling on 478 MW of grid-switchable resources in ERCOT and curtailing up to 127 MW of non-firm export capacity.

Operations engineer Ricky Finkbeiner noted SPP was able to avoid making emergency energy transactions, as MISO did in January 2018. (See Louisiana Regulators Question MISO South Max Gen Event.) The RTO had secured long-lead resource commitments ahead of time as part of its “uncertainty process.”

“The [reliability coordinators] were talking well before the afternoon it occurred,” Finkbeiner said.

Real-time prices spiked to nearly $1,500/MWh before non-firm exports were curtailed.

SPP, which had been operating under conservative operations since 9 a.m., issued the EEA 1 at 2:45 p.m. Load peaked at 49,389 MW at 4:24 p.m., with wind and solar energy making minimal contributions (1,553 MW and 140 MW, respectively). Wind production during the EEA was about 7% of its installed capacity.

The emergency event ended at 7 p.m.

The RTO has operated under conservative operations seven times during the summer because of generation outages, higher loads and subpar wind production.

Committee Questions Latest Joint Study with MISO

Following a third unsuccessful attempt by SPP and MISO to agree on joint transmission projects, committee members asked staff why a congested flowgate responsible for almost half of the market-to-market (M2M) settlements between the RTOs wasn’t more of a factor in the studies.

The Neosho-Riverton 161-kV flowgate in eastern Kansas has accumulated more than $29.3 million in M2M settlements to SPP since the RTOs began the process in March 2015. That is four times the next nearest flowgate and 45.6% of the overall M2M total.

Staff said the grid operators looked at 25 projects in the area but were unable to find enough benefits to justify a solution. Their latest attempt to determine joint projects ended this summer without success. (See MISO, SPP Empty-handed After 3rd Project Study.)

“It seems a lot of needs are showing, but you’re not finding projects,” said committee Chair Jim Jacoby, of American Electric Power. “Is it that there just isn’t enough [adjusted production costs] to justify? Are the calculations skewed?”

“The benefits just weren’t there,” Interregional Coordinator Adam Bell said. “SPP showed some good benefits, but MISO didn’t.”

Bell, who will soon leave his position for another in the organization, said modeling differences and how futures are weighed are the “likely culprits” for the inability to find joint projects. He said MISO uses four futures and three model years in its studies, while SPP uses two of each.

He also pointed out that M2M payments and APC are two different metrics. M2M payments capture the effect of market flows compared to firm flow entitlements, while APC captures the impact of pool-wide dispatch.

A recent upgrade to the Neosho-Riverton flowgate expanded its capacity by 20 MW, resulting in “considerably less” congestion this year, staff said.

“We would be remiss not to at least examine the issue,” the Missouri Public Service Commission’s Adam McKinnie said, suggesting it would be worthwhile to use avoided M2M payments as a benefit, as MISO does for targeted market efficiency projects.

“On the MISO-PJM seam, this project type looks at less expensive projects, requires payback over a short time period and has [been] shown to get results,” McKinnie said.

Bell said a final report on the RTOs’ 2019 Coordinated System Plan study will be included in the background materials for October’s Markets and Operations Policy Committee meeting. An advance copy will be shared with the SSC, he said.

July M2M Settlements Nearly Even Out

July resulted in the lowest M2M settlement between SPP and MISO since the RTOs began the process in March 2015, with the latter incurring $35,455 in M2M charges.

Permanent flowgates were binding for 227 hours and resulted in $753,755 in SPP’s favor. Temporary flowgates were binding for 323 hours, accounting for $718,300 in MISO’s favor.

July's M2M report was reviewed at the SPP Seams Steering committee
July’s market-to-market report | SPP

SPP has accumulated more than $64.3 million in M2M settlements since 2015. The RTO has seen positive settlements in 39 of 53 months through July.

Jacoby Nominated to 2nd Term as Chair

SPP Seams Steering Committee Chair Jim Jacoby
SSC Chair Jim Jacoby, AEP | © RTO Insider

Members nominated Jacoby to serve a second two-year term as the SSC chair. The term, which begins in January and expires December 2021, will be Jacoby’s second full term since succeeding Nebraska Public Power District’s Paul Malone in January 2017.

Jacoby’s nomination will now go before the Corporate Governance Committee for final approval.

The committee elected GridLiance’s Bary Warren to remain its vice chair. Both votes were unanimous.

Members also made their first change to the committee’s scope since 2016, adding that it will “seek opportunities to coordinate with neighboring stakeholder groups to address issues of common interest, such as market-to-market.” The CGC will have the final say on the scope change as well.

— Tom Kleckner

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No ‘Hiccups’ for West’s RC Transition

By Robert Mullin

SEATTLE — All systems are go as the Western Electricity Coordinating Council enters the final stretch of a yearlong sprint to ensure its dozens of balancing authorities safely integrate into new reliability coordinators ahead of Peak Reliability’s dissolution in early December, the group’s board heard Wednesday.

Branden Sudduth, WECC
Branden Sudduth, WECC | © ERO Insider

The Western Interconnection’s transition from two RCs to four is on schedule and proceeding smoothly, according to Branden Sudduth, WECC vice president of reliability planning and performance analysis.

“I am amazed at the amount of effort that people across the interconnection have put into this transition, making it successful, and I’m pleased to report that as of today, we are on schedule to attain all the objectives that we set out to attain,” Sudduth told board members at their quarterly meeting, held in conjunction with WECC’s broader annual gathering.

After Peak announced in July 2018 that it would wind down operations by the end of this year, CAISO and SPP scrambled to pick up its RC customers throughout the West.

CAISO’s RC West — which went live as California’s RC in July — will ultimately take on nearly three-quarters of the West’s load, followed by SPP at about 14%. (See CAISO Finalizes 32 RC Agreements.) BC Hydro began serving as its own RC on Sept. 2, Sudduth noted.

Alberta Electric System Operator has traditionally functioned as its own RC and will continue to do so.

Sudduth said that Gridforce Energy Management — a fifth prospective RC — will delay its certification and instead contract with RC West to serve its generation-only balancing areas for 17 months. As recently as May, Gridforce said it was still targeting a Dec. 3 go-live date, while acknowledging being in “catchup mode.” (See New RCs Tell WECC Transition on Schedule.)

WECC’s certification team for RC West’s future footprint outside California conducted a site visit at CAISO in late July. RC West began shadow operations with Peak for that expanded area on Sept. 4. WECC’s SPP team visited that RC in mid-August and has scheduled a follow-up visit for Oct. 9. SPP RC staff will shadow Peak in October and November and take over its new inland West territories on Dec. 3.

“A lot has happened on the certification and shadow operations front over the last couple of months, and there’s still a lot left to do, but everything is on schedule,” Sudduth said.

Among the tasks still left to wrap up: the completion of efforts to satisfy NERC reliability standard IRO-006-2, which requires a “common interconnection-wide modeling and monitoring methodology” for use in operational planning and real-time assessments, including facility ratings, thermal limits and steady-state voltage limits. NERC approved the standard to ensure uniformity among RCs across the West in the wake of Peak’s closure. (See “Trustees OK WECC Variance; Questions on Gen-only RC, Calif.-Ariz. Seam,” NERC Standards News Briefs: May 8-9, 2019.)

Also, 22 out of 60 WECC entities have still yet to sign on to the Western Interconnection Data Sharing Agreement (WIDSA), which was finalized in July, Sudduth said. The WIDSA will replace the Peak-administered Universal Data Sharing Agreement (UDSA), which provides a “consent-based” platform for sharing reliability-related information in the region.

On a related front, WECC is leading the transition from the Peak EHV Data Sharing Pool — the system used to share grid reliability data under the UDSA — to the Western Data Sharing Pool.

“I don’t know all the technical details of what this means, but essentially what we’re doing is going from an organization like Peak being the central repository of information to developing a new way for the RCs to communicate with each other and directly with their entities — and we’re hoping to transfer to this by Oct. 1,” Sudduth said.

WECC is also guiding the hand-off of Peak’s WECC Interchange Tool (which facilitates interchange between BAs) and Enhanced Curtailment Calculator (used for congestion management), Sudduth said.

He noted that WECC has rolled out a new RC messaging system. “I’ve been getting tons of emails from the new RCs, so it’s good to see that happening,” he said.

‘Reliability is Still Our Mission’

Making an impromptu appearance before the board, Peak CEO Marie Jordan assured WECC stakeholders that the organization’s impending shutdown won’t hold any surprises.

“We can still measure operations, which I think is really important with the magnitude of what we do … that we have this ability to measure it every day to ensure that we don’t have hiccups — because I think that would be very difficult in this transition period,” Jordan said.

WECC board member Ric Campbell and Peak Reliability's Marie Jordan
WECC board member Ric Campbell and Peak Reliability’s Marie Jordan | © ERO Insider

She said Peak is focused on ensuring that staff use the shadow operations periods to transfer knowledge to the new RCs “because reliability still is our mission, and it’s been our first foot forward in all our conversations with our employees and how we’ve worked through the transition.”

As for Peak’s financial condition?

“I’ll say that’s actually in good shape,” Jordan said. She said learning how to close a not-for-profit has “been an interesting journey.”

“But the good news is we’ve done very well on the financial front, and we intend to finish and close that way.”

Jordan said Peak has not experienced any “unplanned attrition” in the past three months and that it plans to release its remaining staff on Dec. 13, just 10 days after handing off oversight to SPP. The company will then move to a model in which a board-appointed trustee will handle closing activities in 2020 as well as manage Peak’s data — and data requests — for the next five years.

“We’ve worked with all our vendors on the contracts … making sure that Peak is released from the liability and all the pieces of the contract with OATI — and all those other types of contracts, making sure there’s a clean start with the new entity,” Jordan said.

“I think we’re wrapping up well.”